No abstract

Moisture significantly affects the adsorption capability of gas shales for methane (CH4), the main component of shale gas. Primary moisture, i.e., the moisture that exists in in situ shale reservoirs, is therefore crucial to estimate and produce shale gas resource. Aiming to understand the influences of primary moisture on CH4 adsorption on shale samples, the occurrence of primary moisture in shales gathered from the Lower Silurian Longmaxi Formation located in southern Sichuan Basin of China was experimentally investigated. Additionally, the primary moisture dependence of CH4 adsorption equilibrium and thermodynamics of shales was investigated. Results indicate that the primary moisture contents of the four shale samples vary between 0.64 and 0.82% (mass percentage), positively correlated with the clay mineral content of shale samples. The adsorption equilibrium behavior regarding water vapor on shales well follows the modified Brunauer–Emmett–Teller (BET) equation. The water vapor is typically adsorbed onto the primary adsorption sites of shale samples, i.e., the oxygenic functional groups consisting of COOH, conjugated CO, and highly conjugated CO, and the secondary adsorption sites, i.e., the previously adsorbed water molecules and clay minerals. The pores with pore diameter less than 4 nm of shales are the main accommodation space for primary moisture. The adsorption equilibrium of CH4 on primary moisture-containing shales well obeys the Ono–Kondo lattice equation. On the basis of the modeling results, the primary moisture causes a remarkable reduction in maximum CH4 adsorption capacity of shale samples by 12.86–45.45%. Moreover, the primary moisture reduces the isosteric heat of CH4 adsorption on shale samples. In summary, the primary moisture in gas shales decreases the adsorption affinity between CH4 and shale samples. Therefore, focusing on the effects of primary moisture on CH4 adsorption on shales is vital to better estimate and produce shale gas resource.

No abstract

No abstract

No abstract

No abstract

No abstract

China Offshore oilfield is rich in heavy oil, M oilfield in Bohai Bay is themost thick heavy oil field in offshore by far with the formation oil viscosityas high as 450 ~ 950mPa.s. Using conventional oil field development (depletionand water flooding), the heavy oil field exposed its limits, such as lowproductivity of single well, low production rate and low predictedrecovery. As we all know, the development effect of thermal recovery is not only relatedwith the thermal recovery methods (steam stimulation, steam flooding, etc.), but also related with the thermal medium (steam, hot water, flue gas etc.). Anew thermal media called multi-thermal fluid, which contains steam, hot waterand flue gas was researched for horizontal well stimulation, which is to injectN2 and CO2 at the same time when injecting steam. This multi-thermal fluidcould employ various mechanisms of each fluid, including reducing oil viscosityby heating and dissolving gas, increasing pressure by injecting gas, expandingheating range, reducing heat loss and gas assisting gravity drive etc. With theadvantages of single thermal injection, this method made up the disadvantagesof single thermal fluid injection and can improve steam stimulation effect insome special formation conditions. In this article, the author first analyzed the characterization ofmulti-thermal fluid, and then researched its stimulation theory. Based on thistheory, the single element of geological data, such as dip angle, permeability, rock compression coefficient, formation thickness, oil viscosity, and injectiondata, such as injection volume, gas-water-ratio and CO2 concentration wasanalyzed using numerical simulation software. Based on this result, selectingdata that make more contribution in incremental oil, production rate, and EORto make sensitivity study to summarize formation that multi-thermal fluid couldbe applied.